Global LNG demand is projected to grow nearly 5% in 2025 and 2026, driven primarily by Europe with almost 30 Bcm of regasification capacity coming online (mainly in Germany) to replace Russian piped gas. In contrast, LNG demand growth in China is expected to slow in 2025, due to increased piped flows from Russia via the Power of Siberia pipeline (almost 40 Bcm/y). For South and Southeast Asia, LNG will remain a crucial baseload fuel to support rapidly expanding economic growth. However, global LNG supply growth remains constrained in the short term, as construction of LNG facilities, particularly in the US, faces significant delays. This results in an overall tight market balance, which could impact prices, mainly in winter.

Global LNG demand is expected to grow towards 660 Bcm by 2027, before gradually slowing down and stabilizing below 5% year-on-year, in line with a structural shift towards renewables for electricity generation and global improvements in energy efficiency. Assuming no further delays, the new wave of liquefaction capacity, primarily driven by the US and Qatar, will be in full swing, effectively eliminating the risk of market tightness and paving the way for a gradual normalization of global LNG prices.

In the long term, pressure on the LNG market is expected to ease as new capacity expands and green energy commitments take effect.

In our Reference scenario, the TTF yearly average for 2025 and 2026 is projected to remain elevated, above 30 €/MWh, due to a fragile market balance and potential pressure from geopolitical tensions. Storage dynamics will play a crucial role, as a faster withdrawal compared to the previous two years could lead to higher prices during the 2025 summer season, coinciding with the refilling season.

From 2027 onwards, further normalization is expected due to the significant deployment of new liquefaction capacity. Assuming progressive growth in global LNG supplies and an acceleration of the energy transition, European gas prices are projected to steadily decline towards 30 €/MWh by 2028.

The European decarbonization process will continue to reduce gas demand, gradually pressuring prices back towards the long-term equilibrium of 25 €/MWh. In the Low Res scenario, geopolitical tensions could leave commodity shortages unresolved, keeping prices just below 45 €/MWh in the long term. In contrast, effective green policies, supported by economic growth, could push prices significantly lower in the High Res scenario, with the TTF averaging near 10 €/MWh in the long term.

The PSV-TTF spread is expected to stay near 2 €/MWh on average, both in 2025 and in 2026, as Italy’s reliance on piped gas flows from Norway via Passo Gries remains high. Fluctuations throughout the year are anticipated to be in line with seasonality.

Flows from the TAP and Algeria, along with LNG arrivals, are expected to partially replace imports from the North in the medium term, leading to a progressive narrowing of the spread to below 1 €/MWh by 2030.

The PSV-TTF spread is expected to converge towards zero in the long term, as flows rebalance from North to South and LNG, combined with the underlying demand reduction driven by decarbonization, plays a key role.

We expect both the 2025 and 2026 PSV yearly averages to remain just below the 35 €/MWh threshold, despite subdued demand growth. The conditions for the Italian gas market stabilization are unlikely to be met in the next couple of years. However, the entry of the Ravenna regasification terminal (5 Bcm/y of capacity) in 2025 may help alleviate some of the pressure, which, however, remains high.

The PSV is expected to follow the mid-term normalization of European gas prices towards 30 €/MWh by 2030, as a gradual rebalancing of the global gas demand-supply dynamics aligns with the anticipated acceleration of the energy transition.

The PSV reference price is expected to stabilize, aligning with TTF prices at around 25 €/MWh in the long term.

The ARERA Resolution 599/2024 confirms all downstream PSV variable components for Q1-25, as anticipated. The only exception is the RET component, which covers costs related to White Certificates and efficiency measures, along with a refund mechanism for thermoelectric producers, covering nearly 40% of costs. The RET component will increase from 1.1 €/MWh to 2.6 €/MWh starting in July 2025, due to uncertainties and delays in the 2025 regulatory framework for White Certificates definition. The same Resolution confirms that thermoelectric producers can request an exemption of over 60% of the CRVOS component (which covers storage injection incentives) for Q1-25. The remaining losses, stemming from extra costs incurred from 2022 emergency gas purchases (nearly 5 billion euros), will be recovered through final customers’ bills over five years. The CRVBL component (covering charges related to gas system balancing activities) will be zero starting January 2025, thanks to the improved natural gas price scenario. As a precautionary measure, we assume a gradual return to historical average levels in the second half of 2025 to account for the volatility of the current transport cost environment, which impacts prices.

A gradual normalization of the average variable logistic costs below 4 €/MWh is only expected beyond 2028, coherently with the foreseen normalization of gas prices and the recovery of the storage-related losses, nearing 1.6 €/MWh on average by 2030.

In our Reference scenario, the average CO2 price for 2025 is projected to spike above 85 €/ton, driven by the ETS reform kick-off. The phasing out of free allowances for aviation (50% by 2025) and the removal of 90 million permits in 2024 are expected to put upward pressure on allowance prices by reducing supply. The inclusion of the maritime transport sector will further increase demand. However, concerns linger about the pace of demand recovery, which is expected to be slow due to ongoing economic challenges.

The supply-demand gap is expected to widen starting in 2026 as the maritime sector joins the ETS and the phasing out of free aviation allowances is fully implemented. By 2030, the Market Stability Reserve’s reinforcement and an increase in the Linear Reduction Factor to 4.4% will further tighten the market, pushing the average CO2 price towards 110 €/ton.

By 2034 the removal of free allowances for sectors covered by the CBAM will reach full implementation, inducing a further increase in allowances demand. Long-term targets depend on the ETS system’s efficiency, with the CO2 price projected to exceed 120 €/ton by 2040 in the Reference scenario and potentially approach 150 €/ton in the Low scenario, assuming stricter decarbonization efforts in Europe.

Coal-fired units are set to phase out by 2025, except for those in Sardinia, which will remain operational until the Tyrrhenian Link is completed—projected for 2030 in the Reference case and 2029 in the Low case. By 2030, RES are expected to supply around 47% of total electricity demand.

Renewable energy is projected to reach 70% of the energy mix by 2040 and 85% by 2050. The share of gas-fired thermal plants will reach 10% by 2050. Favorable market conditions will promote the development of energy-intensive storage solutions, thereby enhancing their contribution to the energy mix.

A rapid surge in decarbonization efforts is driven by rising commodity prices, increased EU ETS costs, and streamlined approval processes for new renewable projects, all of which collectively boost investment in energy efficiency. The phase-out of coal-fired units across the peninsula is projected by 2025. Gas-fired thermal plants are expected to supply up to 34% of national electricity demand by then, with net electricity imports exceeding 49 TWh.

By the end of 2028 coal-fired units are entirely phased-out. Falling renewables’ costs and a greater effort to reach decarbonization goals support renewables development. In 2030 the ratio between renewable energy and total electricity consumption reach 59%. Improvements in the electricity grid will facilitate the reduction of electricity imported from neighborhood countries.

In the long term, gas-fired thermal plants will remain essential for system security, but their share of the energy mix is expected to decrease to 15% by 2040 and 6% by 2050 as storage capacity expands. Despite advancements in storage and grid improvements, achieving full renewable integration will face challenges such as grid congestion and overproduction, underscoring the need for greater electrolyzer capacity to effectively manage surplus renewable energy.

Coal-fired thermal plants remain a significant power source, but lower gas prices will increase the share of gas-fired plants to 32% of demand. Net imports are expected to stabilize at 49 TWh in 2025, reducing coal generation from 7 TWh in 2024 to to 5 TWh.

CM-led investments are set to come online, but the phase-out of coal-fired capacity is delayed until 2035, coinciding with the completion of significant network investments. By 2030, net imports are expected to decline to just over 44 TWh, while gas-fired generation will account for 35% of total electricity demand. Hydroelectric output is projected to stabilize around 46.5 TWh per year, with renewable energy sources steadily increasing their share in the energy mix.

The projected rise in CO2 prices is expected to further erode the competitiveness of coal generation, leading to its full phase-out by 2035 with the completion of the Tyrrhenian Link. Meanwhile, gas-fired generation is anticipated to account for 22% of the energy mix by 2050. The evolving dynamics of the Day-Ahead Market (DAM) and the continued expansion of renewable energy sources will support the long-term integration of 10 GW of energy-intensive storage.

Electric vehicle (EV) numbers are projected to reach 1.2 million by 2025, 4.5 million by 2030, and 11.1 million by 2040 in the Reference scenario, resulting in total consumption of 2 TWh, 7.6 TWh, and 18.7 TWh from EVs, respectively. In the High RES scenario, a more rapid adoption of electric vehicles is expected to reach 6 million by 2030 and 15 million by 2040. Conversely, in the Low RES scenario, the development of e-mobility experiences a 5- to 10-year delay compared to the Reference scenario, with the target of 4.5 million EVs only being achieved by 2040.

The NIECP envisages 6.5 million electric vehicles in Italy in 2030 - 4.3 million are pure EVs (BEV: Battery Electric Vehicles) – accounting for about 8 TWh of additional electricity demand. In our Reference view we estimate additional 7.5 TWh to come from BEV and PHEV (Plug-in Hybrid Electric Vehicle). This means that our hypotheses consider a greater consumption per EV compared to NIECP figures. Main differences are most likely connected to the underlying assumptions about e-mobility applications in cities or long-term transport.

Despite the recent Green Deal proposals at the EU level regarding transportation, the uncertainty surrounding the future expansion of a market still in its early stages of development leads us to assume a business-as-usual (BAU) trend over the long term, beginning with the annual level of electric vehicle (EV) additions projected for 2030.

Heating and cooling (H&C) is projected to represent additional electricity requirements ranging from 2 TWh to 5 TWh in 2025, 4 TWh to 13 TWh in 2030, and 8 TWh to 17 TWh in 2040, depending on the scenario analyzed.

Our assumptions lead to estimate 6.7 TWh of H&C consumption in 2030, as per the reference scenario, corresponding to around 1.8 million installations for civil uses.

We assume a BAU trend in the long-term horizon, starting from the annual level of additional installations and consumption reached in 2030.

Law 91/2014 affirms that grid and general system tariff components should be applied to the electricity consumed and not only to the electricity withdrawn from the public grid. Following this approach, the exemptions accorded to RIU (Re Interne di Utenza) and SEU (Sistemi Efficienti di Utenza) and closed distribution systems, and the benefits currently in force for existing plants related to self-consumption will be at least partially removed for new subjects/projects that apply for similar mechanisms.

The excess of self-produced electricity that is not consumed by the industrial sites (self-consumption) and is thus sold on the market (differential between self-production and self-consumption) is expected to gradually decrease, consistently with the expected end-of-life of existing power plants that serve industrial sites.

In 2015, the approval of the European guidelines on capacity allocation and congestion management (CACM) introduced new parameters to be followed in the zonal configuration review process. In 2018, Terna began a process to review the zonal configurations in compliance with such rules.

The current zonal configuration derives from the base case proposed by Terna in compliance with the CACM. Differences compared to the previous configuration: (i) elimination of the limited production poles, (ii) inclusion of a new bidding zone corresponding to the Calabria region, (iii) displacement of the Umbria region from the Centre-North zone to the Centre-South market zone.

The zonal distribution of electricity demand is based on historical regional data published by Terna and subsequent econometric elaborations. In the Reference case, the zonal distribution of electricity needs is as follows: North (57%), Central-North (9%), Central-South (17%), South (7%), Calabria (2%), Sicily (6%), Sardinia (3%). Slight differences in such figures between the alternative cases are the result of the econometric elaborations performed.

2024 CM capacity should enter the market between late 2024 and mid-2025.

Auction results show also that Sardinia coal-fired capacity will not be substituted by gas-fired units, as only storage capacity was awarded in the island. Anyway, while coal-fired plants on the peninsula will be phased-out after 2025, Sardinia units are expected to operate until the Tyrrhenian Link infrastructure is fully completed (2030).

The amount of capacity auctioned through the CM is expected to grant full system adequacy at least through to 2030. No other thermoelectric capacity investments are envisaged after the wave of investment brought by the last CM auctions. Existing CHP power plants continue to support industrial activities under the assumption of a BAU evolution of the industrial needs they serve. Some ageing CCGT capacity exit the market.

Capacity secured in the 2024 Capacity Market auctions has experienced widespread delays, with notable examples such as the CCGT Ostiglia project now rescheduled for commissioning in February 2026. Most of this capacity is expected to gradually enter the market over the course of 2025.

Auction results show also that Sardinia coal-fired capacity will not be substituted by gas-fired units, as only storage capacity was awarded in the island. Anyway, while coal-fired plants on the peninsula will be phased-out after 2025, Sardinia units are expected to operate until the Tyrrhenian Link infrastructure is fully completed (2029).

No other thermoelectric capacity investments are envisaged after the wave of investment brought by the last CM auctions. Most of existing CHP power plants gradually exit the market, substituted by greener solutions. Some ageing CCGT capacity exit the market following strong competitive conditions.

Capacity secured in the 2024 Capacity Market auctions has experienced widespread delays, with notable examples such as the CCGT Ostiglia project now rescheduled for commissioning in February 2026. Most of this capacity is expected to gradually enter the market over the course of 2025.

Thermal capacity expected to be stable in the second half of the decade in the Low RES scenario.

No other thermoelectric capacity investments are envisaged after the wave of investment brought by the last CM auctions. Existing CHP and CCGT power plants are projected to remain operative. The commissioning of the Tyrrhenian Link is postponed until 2035, determining a delayed phase-out of all coal power plants.

The existing fleet of combined cycle gas turbines (CCGTs) is projected to average approximately 2200 EOH during the 2024-2025 period, exhibiting significant zonal variations. In the Northern zone, the load factor for CCGTs is around 1800 EOH, while the Southern zones show lower figures, averaging about 1000 EOH. Notably, Calabria stands out with an average of 3000 EOH.

After the phase-out of coal-fired units, residual demand is expected to rebound. However, existing combined cycle gas turbines (CCGTs) will face significant competition from sustained import levels and new high-efficiency entrants supported by the capacity market. In the low scenario, residual demand is further reduced due to the effects of energy efficiency improvements and increased renewable penetration. Conversely, in the high scenario, residual demand gradually increases as switching conditions improve.

Existing CCGTs (53%-efficiency) stabilize around 2000 EOH. In the Low scenario, the great renewable penetration influences competitive dynamics and existing units remain close to 1600 EOH. In the High scenario, the improvement of switching conditions is hampered by the high level of imports from abroad, with EOH of existing units over 2000 favored by phase-out after 2035. High-efficiency units stabilize below the 4800 EOH only in the Low scenario.

The decline in electricity demand, coupled with favorable switching conditions, is expected to significantly reduce coal production. In the Reference Scenario, coal output is projected to fall to 2.1 TWh by 2025, while in the High RES Scenario, it will drop further to just above 1 TWh. Conversely, in the Low RES Scenario, coal production is anticipated to reach 5.0 TWh in 2025.

The timeline for coal phase-out differs across scenarios, driven largely by the readiness of key grid infrastructure, particularly the Tyrrhenian Link. In the Reference Scenario, only the units in Sardinia are expected to remain operational beyond 2025, with their retirement aligned to the completion of the Tyrrhenian Link in 2030. In the High RES Scenario, full coal plant decommissioning is anticipated by 2028. Conversely, in the Low RES Scenario, coal-powered units are projected to remain active until 2035.

Coal units remain operative beyond 2030 only in the Low RES scenario, until the complete phase-out projected in 2035, with the entrance of the Tyrrhenian Link.

Market parity conditions, coupled with the FerX incentive scheme, are expected to accelerate the achievement of long-term targets. In the Reference scenario, an ambitious renewable energy expansion plan foresees the installation of 51 GW of solar and 17 GW of wind capacity by 2030, driving the RES share to nearly 50% of total energy demand. This scenario assumes a market-driven evolution. In the High RES scenario, faster declines in technology costs and more favorable economic conditions push capacity growth further, resulting in 63 GW of solar and 19 GW of wind capacity by 2030.

The Reference scenario forecasts a steady increase in renewable energy penetration, with solar capacity projected to reach 80 GW and wind capacity 27 GW by 2040. Accelerating progress towards long-term decarbonization goals may be achievable through higher-than-expected investments in grid infrastructure and advanced energy storage solutions.

Wind generation is projected to surpass 26 TWh while solar generation will approach 42 TWh by 2025. In the High RES scenario, more favorable economic conditions result in even higher projections, with wind reaching 27 TWh and solar approaching 43 TWh within the same period.

Assuming a business-as-usual market trajectory and the resolution of permitting process bottlenecks in the near future, it is expected that 90% of the 2030 RES/GDC target will be met. Full achievement of the 63% target is anticipated only with a greener, more ambitious evolution of the Italian energy system. Meeting the more stringent Green Deal objectives—potentially setting the RES/GDC target around 70%, though still under discussion—would require a significantly greater effort.

The reduction of technology costs and consolidated market parity conditions could allow both solar and wind generation to almost triple by 2040, with respect to 2024 values, in the Reference scenario. Boundary conditions of alternative scenarios lead to different degrees of renewable development and production level.

Under BAU market conditions and moderate renewable penetration, the risk of overgeneration remains low in both the Reference and Low RES scenarios. However, a more significant increase in capacity installation in the South macro-zone could lead to more frequent overgeneration during specific hours in the High RES scenario.

The anticipated increase in renewable energy penetration after 2027 is expected to heighten the risk of overgeneration, potentially resulting in approximately 3 TWh of excess electricity by 2030 in the High RES scenario. This curtailment effect could be further amplified by specific local grid constraints. In comparison, the Reference scenario projects a more moderate level of overgeneration, reaching around 0.7 TWh by 2030. Overall, overgeneration is set to escalate throughout the decade, driven by the rapid expansion of renewables in the Southern regions, and could be exacerbated by delays or inadequacies in grid reinforcement.

To effectively manage the increasing penetration of renewable energy and the resulting overgeneration, substantial investments in grid reinforcement and high-capacity energy storage solutions will be essential throughout the 2030s. These measures will be critical for balancing the grid and maintaining a stable energy supply, particularly in regions more susceptible to overgeneration. Additionally, this excess energy production presents an opportunity to expand electrolysis capacity, which would not only harness surplus energy but also support continued investments in renewable energy sources.

In the long term, the expansion of renewable capacity—particularly in the Southern regions—is expected to significantly increase the incidence of systematic overgeneration, especially on the islands. Grid investments and battery energy storage systems (BESS) will likely prove inadequate to address this issue, thereby creating favorable conditions for the adoption of green hydrogen technologies. In the Reference scenario, installed electrolysis capacity could reach nearly 0.5 GW, predominantly concentrated in Sardinia. Over time, electrolysis capacity can effectively mitigate overgeneration by offering a mechanism to store surplus renewable energy. Moreover, by enhancing demand during periods of high RES production, it can help stabilize prices and alleviate the cannibalization effect, particularly during the later stages of the transition.

Despite potential challenges in securing land and rising land costs, technology costs for solar projects have decreased over the past year. This reduction has been primarily driven by declining panel costs, supported by increased competition among sellers. These trends are supporting the market parity for solar technologies, with baseload prices projected to stabilize between 80 and 100€/MWh during the 2025-2026 period. As a result, solar power plants are expected to capture rates that exceed the estimated levelized cost of electricity (LCOE), ranging between 66 and 82 €/MWh, depending on the market zone.

Despite the potential cannibalization effect on unlevered projects situated in the Southern regions, decling investement costs for solar projects and expected captured prices above 80 €/MWh support return on investements for pv plants.

The long-term outlook for the renewable energy sector from 2030 onwards

appears promising, driven by the continuous decline in technology costs

and the adoption of enhanced Power Purchase Agreement (PPA) best

practices, which are expected to bolster non-incentivized investments.

However, the cannibalization effect may emerge as a significant concern

in specific regions, such as Sardinia and Sicily, where the grid

infrastructure may lack the capacity to efficiently manage and redirect

energy flows.

Market parity continues to be guaranteed for wind plants despite the investement intensity of those projects, benefitting of their wider generation profile capable of capturing higher prices than solar plants. This is largely due to their broader generation profile, which allows wind projects to capture higher prices compared to solar plants. With annual captured prices aligning closely with baseload prices, wind power plants are expected to cover LCOE levels ranging between 85 and 90 €/MWh, in all the zones.

Gradual reduction in investement costs for wind projects and captured prices close to 90€/MWh support wind market parity in the mid-term. Potential price cannibalizzation dynamics remain limited untill 2030, as a strong capacity development is expected to accelerate during the 2030s. However, site-specific factors may still influence the economics of individual projects.

The long-term outlook from 2030 onwards appears promising, driven by the ongoing decline in technology costs and the adoption of enhanced Power Purchase Agreement (PPA) best practices that support non-incentivized investments.

Intra-day price spreads on the Day-Ahead Market (DAM) may reveal opportunities for pumped hydro units; however, the Ancillary Services Market, particularly during the real-time balancing phase, is anticipated to remain their primary source of revenue. Pumped hydro production is projected to hover around 2.5 TWh.

Under an accelerated RES development path compared to the BAU trajectory, pumped hydro production could reach 3.9 TWh by 2030 in the High RES scenario, driven by new opportunities emerging in the DAM as RES penetration increases. In contrast, the Low RES scenario limits pumped hydro production to around 2 TWh.

As non-programmable renewable sources exceed 50% of total electricity demand, market opportunities are set to grow further. Pumped hydro units will play a pivotal role in reducing the solar cannibalization effect and alleviating network congestion, with production projected to reach nearly 7 TWh by 2050.

In the coming years, all projects assigned through the Fast Reserve auctions, held in December 2020 as part of Terna’s pilot initiative to provide ultra-fast frequency regulation services, are expected to become operational. In addition, the Capacity Market auction of 2024 started the development of energy-intensive storage in the Italian market, with over 1.5 GW of new storage capacity, mainly consisting of energy-intensive systems with a duration of 4 hours, starting to enter into the market.The ongoing installation of distributed storage capacity could also lead to a total electrochemical storage capacity of more than 15 GWh.

The anticipated growth of storage capacity in the coming years will play a pivotal role in integrating non-programmable renewable energy, enhancing the stability and flexibility of the national electricity system. Italy’s PNIEC sets an ambitious target of 72 GWh of additional storage capacity by 2030, spanning both utility-scale and distributed projects. Utility-scale development will primarily focus on Southern regions, where non-programmable renewable generation is most concentrated. The Italian storage market currently boasts a substantial pipeline of projects, either authorized or under evaluation, with their realization heavily reliant on the support of regulated mechanisms. Key among these is the MACSE auction, planned for mid-2025, which aims to develop capacity predominantly in the South and on the islands. By 2030, total BESS capacity, including both small-scale and utility-scale systems, is projected to range between 48 and 65 GWh.

Energy-intensive applications are expected to continue their growth, driven by market signals linked to the expansion of renewable energy installations. Under the Reference scenario, the PNIEC targets are anticipated to be achieved by the mid-2030s. Storage capacity is projected to reach 105 GWh in the Reference scenario by 2040, with an increase to 140 GWh in the High RES case.

The favorable price spread between evening and midday hours is anticipated to persist in the short term, as the penetration of renewables remains below 50% of gross domestic consumption.

The continued expansion of solar capacity is expected to further suppress midday prices, particularly during periods of abundant sunlight and low demand, such as in spring. This trend will progressively narrow the disparity between peak and off-peak prices.

The long-term persistence of reversed hourly price differentials is expected to drive higher prices during off-peak hours. The growing integration of energy-intensive electrochemical storage systems, coupled with improved storage unit operability, is likely to alleviate the cannibalization effect caused by non-programmable solar power plants.

The moderation of commodity prices, increased net imports from foreign countries, and a sluggish recovery in demand are heightening market competition for CCGTs. As a result, a negative CSS of approximately -2.3 €/MWh is anticipated for thermal plants in the Reference scenario for 2025.

In the latter half of the 2020s, intensified competition from newly constructed Capacity Market units, a growing share of RES, and downward pressure from normalized gas prices are expected to keep the CCS in negative territory, averaging -3.5 €/MWh.

In the long term, renewables are expected to dominate the generation mix, driving down both power prices and the CSS, which is projected to reach approximately -30 €/MWh by 2050. Despite rising demand, existing CCGTs are expected to remain the marginal technology, operating as such for around 80% of the system’s hours in 2040.

The impact of solar production during peak daytime hours is still modest due to limited penetration. As a result, price differentials throughout the day are currently at average levels.

As solar penetration increases and the cannibalization effect intensifies, the disparity between central hours and morning/evening peak hours grows wider. While the combined deployment of single-axis trackers, grid enhancements, and energy-intensive storage solutions helps alleviate this issue, its impact remains limited.

As renewable penetration advances, both intra-day price differentials and the number of hours with prices at 0 €/MWh increase, encouraging investments in electrolysis capacity. This scenario makes time-shifting applications in the Day-Ahead Market appealing and stimulates new investments in energy-intensive storage units.

The anticipated energy outlook, characterized by stagnant electricity demand, a growing share of RES, and increased import levels, is expected to intensify competition for the existing fleet. These factors will place downward pressure on the CSS for CCGTs, with average values projected at -2.7 €/MWh over the 2025-2026 period.

Market competition is set to intensify with stabilized imports from Northern borders, increased renewable capacity, and new high-efficiency CCGTs from CM auctions. These factors will keep baseload CSS negative, averaging around -3.5 €/MWh in the High RES scenario, where accelerated RES growth and heightened thermoelectric competition amplify the pressure in the second half of the 2020s.

Post-2030, the decommissioning of aging capacity will enable existing CCGTs (53%-efficiency) to remain the marginal technology for approximately 80% of the operating hours through 2040. During this horizon, baseload CSS is expected to range below -2 €/MWh, and until -6 €/MWh. In the High RES scenario, baseload CSS is projected to fall further, staying below -7 €/MWh in the long-term (post-2040). Conversely, in the Low RES, increased CCGT generation will result in higher baseload CSS, though it is still expected to remain below -4 €/MWh from 2040 onwards.

Captured CSS evolve depending on the zone mix, with southern bidding zones suffering the high operativity of coal-fired units and significant risk of operation at loss, while CCGT producing in the northern zone manage to guarantee positive margins at around 11 €/MWh , favored by the current market dynamics.

As renewable capacity increases, existing units tend to concentrate their operations during evening hours to maximize captured margins. The high-efficiency gas-fired capacity captured CSS is subject to competitive market conditions as new projects enter the market with support from the latest CM auction. Despite this, the high efficiency of these projects enables them to maintain an average captured margin of 10 €/MWh.

Growing renewable penetration intensifies overgeneration phenomena and accentuates evening price spikes, determining an increasing trend for captured marginality for existing units in the first half of the 2030s, but load factors reduce progressively on increasing renewables share and increase competition from high efficiency units.

Solar power plants stand to benefit from projected moderate increases in power prices, with captured prices varying between approximately 94€/MWh and 100€/MWh in the Northern zone, depending on the technology (Tracker or Fixed Tilt). In the Southern zones, captured prices range between 77€/MWh and 88€/MWh.

The accelerating rate of RES installations, along with the resulting cannibalization and overgeneration effects — only partially mitigated by energy storage systems and grid improvements — is influencing zonal captured prices. These prices are diverging from baseload prices and are projected to fall below 90 €/MWh by 2030, even in the Northern zones.

The growing frequency of overgeneration highlights the need for energy-intensive storage systems to partially mitigate the cannibalization effect. After 2030, this effect intensifies for solar captured prices, especially in Southern market zones with higher renewable penetration, driving long-term prices below 50 €/MWh in both Northern and Southern regions.

Captured prices are closely aligned with zonal baseload prices and benefit from a modest uptick in power prices, with values nearing 100 €/MWh across all zones.

Captured prices remain closely aligned with zonal baseload prices over the long term. Increased solar production leads to overgeneration in the early 2030s, but outcomes for both sources are shaped more by zonal market dynamics than price trends. By 2030, captured prices exceed 95 €/MWh in the Northern zones and approach 90 €/MWh in the South, supported by a more balanced production profile across the day and year.

The high competition in the PV modules market, predominantly led by Chinese manufacturers, has driven the costs of PV modules down to around €150,000 per MW. Nearly 30% of the total cost for a module is attributed to polysilicon, a relatively inexpensive but highly volatile material. Other critical materials with high demand and low availability, such as silver, could potentially increase the price of the technology in the future. Generally, due to market competitiveness, PV modules account for only 15% of the total solar CAPEX. Two significant costs impact the total CAPEX for solar technologies. The cost of connecting to the grid, which varies greatly by project, is expected to rise in the coming years. This is due to the increasing number of projects in remote locations, complicating high-voltage grid connections. Additionally, the cost of land acquisition or rental, which constitutes nearly 8% of the total cost, has increased in recent years. The anticipated acceleration of new installations in the coming years may further drive up land demand for solar projects, as available sites diminish, thereby increasing rental costs. This cost structure typically results in an IRR of around 7% (base case considering South zone, pre-tax captured prices, 30 years time horizon) for solar projects, with regional variations according to different zonal captured prices. For agri-voltaic projects, a markup of 20%-40% on the total investment cost must be applied, leading to a lower expected IRR of around 6%.

The primary cost for a wind plant is the turbine and inverter, which account for 60% of the total cost. Grid connection represents 10% of the wind CAPEX, which is approximately €1.5 million for an onshore wind project. In the short and mid-term, technology costs are unlikely to decrease due to the low rate of new installations, which limits the potential for economies of scale. However, as the technology matures, particularly in Northern countries where installation rates are higher, there may be a reduction in technology costs. Despite this, the CAPEX for a wind project is expected to remain above €1 million until 2040. This cost structure typically results in an IRR of around 7% (base case considering South zone, pre-tax captured prices, 20 years time horizon) for onshore wind projects.

Captured prices closely align with zonal baseload prices and benefit from elevated power prices.

Captured prices are expected to remain closely aligned with zonal baseload prices in the long term. The overgeneration resulting from increased solar production significantly influences the early 2030s; however, the performance of both sources remains more closely tied to zonal market dynamics than to changes in price structure. Additionally, both sources benefit from a production profile that is more evenly distributed throughout the day and across the year.